Tachometer for a rotating control device

ABSTRACT

A rotating control device (RCD) includes: a tubular housing having a flange formed at each end thereof; a stripper seal for receiving and sealing against a tubular; a bearing for supporting rotation of the stripper seal relative to the housing; a retainer for connecting the stripper seal to the bearing; and a tachometer. The tachometer includes a probe connected to the retainer and including: a tilt sensor; an angular speed sensor; an angular acceleration sensor; a first wireless data coupling; and a microcontroller operable to receive measurements from the sensors and to transmit the measurements to a base using the first wireless data coupling. The tachometer further includes the base connected to the housing and including: a second wireless data coupling operable to receive the measurements; and an electronics package in communication with the second wireless data coupling and operable to relay the measurements to an offshore drilling unit.

BACKGROUND OF THE DISCLOSURE

1. Field of the Disclosure

The present disclosure generally relates to a tachometer for a rotatingcontrol device.

2. Description of the Related Art

Drilling a wellbore for hydrocarbons requires significant expendituresof manpower and equipment. Thus, constant advances are being sought toreduce any downtime of equipment and expedite any repairs that becomenecessary. Rotating equipment is particularly prone to maintenance asthe drilling environment produces abrasive cuttings detrimental to thelongevity of rotating seals, bearings, and packing elements.

In a typical drilling operation, a drill bit is attached to a drillpipe. Thereafter, a drive unit rotates the drill pipe using a drivemember as the drill pipe and drill bit are urged downward to form thewellbore. Several components are used to control the gas or fluidpressure. Typically, one or more blow out preventers (BOP) are used toseal the mouth of the wellbore. In many instances, a rotating controldevice is mounted above the BOP stack. An internal portion of theconventional rotating control device is designed to seal and rotate withthe drill pipe. The internal portion typically includes an internalsealing element mounted on a plurality of bearings. Over time, the sealarrangement may leak (or fail) due to wear.

SUMMARY OF THE DISCLOSURE

The present disclosure generally relates to a tachometer for a rotatingcontrol device. In one embodiment, a rotating control device (RCD) foruse with an offshore drilling unit includes: a tubular housing having aflange formed at each end thereof; a stripper seal for receiving andsealing against a tubular; a bearing for supporting rotation of thestripper seal relative to the housing; a retainer for connecting thestripper seal to the bearing; and a tachometer. The tachometer includesa probe connected to the retainer and including: a tilt sensor; anangular speed sensor; an angular acceleration sensor; a first wirelessdata coupling; and a microcontroller operable to receive measurementsfrom the sensors and to transmit the measurements to a base using thefirst wireless data coupling. The tachometer further includes the baseconnected to the housing and including: a second wireless data couplingoperable to receive the measurements; and an electronics package incommunication with the second wireless data coupling and operable torelay the measurements to the offshore drilling unit.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the presentdisclosure can be understood in detail, a more particular description ofthe disclosure, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlytypical embodiments of this disclosure and are therefore not to beconsidered limiting of its scope, for the disclosure may admit to otherequally effective embodiments.

FIGS. 1A-1C illustrate a drilling system utilizing a rotating controldevice, according to one embodiment of the present disclosure.

FIG. 2 illustrates the rotating control device.

FIGS. 3A and 3B illustrate a tachometer of the rotating control device.

FIG. 4A illustrates a pocket formed in a stripper retainer of therotating control device for receiving a probe of the tachometer. FIGS.4B and 4C illustrate a pocket formed in a flange of the rotating controldevice for receiving a base of the tachometer.

FIG. 5 illustrates a probe of the tachometer.

FIGS. 6A and 6B illustrate a gyroscope usable with the probe, accordingto another embodiment of the present disclosure.

FIG. 7 illustrates a rotating control device having a data sub,according to another embodiment of the present disclosure.

DETAILED DESCRIPTION

FIGS. 1A-1C illustrate a drilling system 1 utilizing a rotating controldevice (RCD) 26, according to one embodiment of the present disclosure.The drilling system 1 may include a mobile offshore drilling unit (MODU)1 m, such as a semi-submersible, a drilling rig 1 r, a fluid handlingsystem 1 h, a fluid transport system 1 t, a pressure control assembly(PCA) 1 p, and a drill string 10. The MODU 1 m may carry the drillingrig 1 r and the fluid handling system 1 h aboard and may include a moonpool, through which drilling operations are conducted. Thesemi-submersible MODU 1 m may include a lower barge hull which floatsbelow a surface (aka waterline) 2 s of sea 2 and is, therefore, lesssubject to surface wave action. Stability columns (only one shown) maybe mounted on the lower barge hull for supporting an upper hull abovethe waterline. The upper hull may have one or more decks for carryingthe drilling rig 1 r and fluid handling system 1 h. The MODU 1 m mayfurther have a dynamic positioning system (DPS) (not shown) or be mooredfor maintaining the moon pool in position over a subsea wellhead 50.

Alternatively, the MODU 1 m may be a drill ship. Alternatively, a fixedoffshore drilling unit or a non-mobile floating offshore drilling unitmay be used instead of the MODU 1 m. Alternatively, the wellbore may besubsea having a wellhead located adjacent to the waterline and thedrilling rig may be a located on a platform adjacent the wellhead.Alternatively, the wellbore may be subterranean and the drilling riglocated on a terrestrial pad.

The drilling rig 1 r may include a derrick 3, a floor 4, a top drive 5,and a hoist. The top drive 5 may include a motor for rotating 16 thedrill string 10. The top drive motor may be electric or hydraulic. Aframe of the top drive 5 may be linked to a rail (not shown) of thederrick 3 for preventing rotation thereof during rotation 16 of thedrill string 10 and allowing for vertical movement of the top drive witha traveling block 6 of the hoist. The frame of the top drive 5 may besuspended from the derrick 3 by the traveling block 6. A Kelly valve 11may be connected to a quill of a top drive 5. The quill may betorsionally driven by the top drive motor and supported from the frameby bearings. The top drive 5 may further have an inlet connected to theframe and in fluid communication with the quill.

The traveling block 6 may be supported by wire rope 7 connected at itsupper end to a crown block 8. The wire rope 7 may be woven throughsheaves of the blocks 6, 8 and extend to drawworks 9 for reelingthereof, thereby raising or lowering the traveling block 6 relative tothe derrick 3. The drilling rig 1 r may further include a drill stringcompensator (not shown) to account for heave of the MODU 1 m. The drillstring compensator may be disposed between the traveling block 6 and thetop drive 5 (aka hook mounted) or between the crown block 8 and thederrick 3 (aka top mounted).

An upper end of the drill string 10 may be connected to the Kelly valve11, such as by threaded couplings. The drill string 10 may include abottomhole assembly (BHA) 10 b and joints of drill pipe 10 p connectedtogether, such as by threaded couplings. The BHA 10 b may be connectedto the drill pipe 10 p, such as by threaded couplings, and include adrill bit 15 and one or more drill collars 12 connected thereto, such asby threaded couplings. The drill bit 15 may be rotated 16 by the topdrive 5 via the drill pipe 10 p and/or the BHA 10 b may further includea drilling motor (not shown) for rotating the drill bit. The BHA 10 bmay further include an instrumentation sub (not shown), such as ameasurement while drilling (MWD) and/or a logging while drilling (LWD)sub.

The fluid transport system 1 t may include an upper marine riser package(UMRP) 20, a marine riser 25, a booster line 27, and a choke line 28.The UMRP 20 may include a diverter 21, a flex joint 22, a slip (akatelescopic) joint 23, a tensioner 24, and a rotating control device(RCD) 26. A lower end of the RCD 26 may be connected to an upper end ofthe riser 25, such as by a flanged connection. The slip joint 23 mayinclude an outer barrel connected to an upper end of the RCD 26, such asby a flanged connection, and an inner barrel connected to the flex joint22, such as by a flanged connection. The outer barrel may also beconnected to the tensioner 24, such as by a tensioner ring.

The flex joint 22 may also connect to the diverter 21, such as by aflanged connection. The diverter 21 may also be connected to the rigfloor 4, such as by a bracket. The slip joint 23 may be operable toextend and retract in response to heave of the MODU 1 m relative to theriser 25 while the tensioner 24 may reel wire rope in response to theheave, thereby supporting the riser 25 from the MODU 1 m whileaccommodating the heave. The riser 25 may extend from the PCA 1 p to theMODU 1 m and may connect to the MODU via the UMRP 20. The riser 25 mayhave one or more buoyancy modules (not shown) disposed therealong toreduce load on the tensioner 24.

The PCA 1 p may be connected to the wellhead 50 adjacently located to afloor 2 f of the sea 2. A conductor string 51 may be driven into theseafloor 2 f. The conductor string 51 may include a housing and jointsof conductor pipe connected together, such as by threaded couplings.Once the conductor string 51 has been set, a subsea wellbore 90 may bedrilled into the seafloor 2 f and a casing string 52 may be deployedinto the wellbore. The casing string 52 may include a wellhead housingand joints of casing connected together, such as by threaded couplings.The wellhead housing may land in the conductor housing during deploymentof the casing string 52. The casing string 52 may be cemented 91 intothe wellbore 90. The casing string 52 may extend to a depth adjacent abottom of an upper formation 94 u. The upper formation 94 u may benon-productive and a lower formation 94 b may be a hydrocarbon-bearingreservoir.

Alternatively, the lower formation 94 b may be non-productive (e.g., adepleted zone), environmentally sensitive, such as an aquifer, orunstable. Although shown as vertical, the wellbore 90 may include avertical portion and a deviated, such as horizontal, portion.

The PCA 1 p may include a wellhead adapter 40 b, one or more flowcrosses 41 u,m,b, one or more blow out preventers (BOPs) 42 a,u,b, alower marine riser package (LMRP), one or more accumulators 44, and areceiver 46. The LMRP may include a control pod 76, a flex joint 43, anda connector 40 u. The wellhead adapter 40 b, flow crosses 41 u,m,b, BOPs42 a,u,b, receiver 46, connector 40 u, and flex joint 43 may eachinclude a housing having a longitudinal bore therethrough and may eachbe connected, such as by flanges, such that a continuous bore ismaintained therethrough. The bore may have drift diameter, correspondingto a drift diameter of the wellhead 50. The flex joints 23, 43 mayaccommodate respective horizontal and/or rotational (aka pitch and roll)movement of the MODU 1 m relative to the riser 25 and the riser relativeto the PCA 1 p.

Each of the connector 40 u and wellhead adapter 40 b may include one ormore fasteners, such as dogs, for fastening the LMRP to the BOPs 42a,u,b and the PCA 1 p to an external profile of the wellhead housing,respectively. Each of the connector 40 u and wellhead adapter 40 b mayfurther include a seal sleeve for engaging an internal profile of therespective receiver 46 and wellhead housing. Each of the connector 40 uand wellhead adapter 40 b may be in electric or hydraulic communicationwith the control pod 76 and/or further include an electric or hydraulicactuator and an interface, such as a hot stab, so that a remotelyoperated subsea vehicle (ROV) (not shown) may operate the actuator forengaging the dogs with the external profile.

The LMRP may receive a lower end of the riser 25 and connect the riserto the PCA 1 p. The control pod 76 may be in electric, hydraulic, and/oroptical communication with a programmable logic controller (PLC) 75and/or a rig controller (not shown) onboard the MODU 1 m via anumbilical 70. The control pod 76 may include one or more control valves(not shown) in communication with the BOPs 42 a,u,b for operationthereof. Each control valve may include an electric or hydraulicactuator in communication with the umbilical 70. The umbilical 70 mayinclude one or more hydraulic and/or electric control conduit/cables forthe actuators. The accumulators 44 may store pressurized hydraulic fluidfor operating the BOPs 42 a,u,b. Additionally, the accumulators 44 maybe used for operating one or more of the other components of the PCA 1p. The PLC 75 and/or rig controller may operate the PCA 1 p via theumbilical 70 and the control pod 76.

A lower end of the booster line 27 may be connected to a branch of theflow cross 41 u by a shutoff valve 45 a. A booster manifold may alsoconnect to the booster line lower end and have a prong connected to arespective branch of each flow cross 41 m,b. Shutoff valves 45 b,c maybe disposed in respective prongs of the booster manifold. Alternatively,a separate kill line (not shown) may be connected to the branches of theflow crosses 41 m,b instead of the booster manifold. An upper end of thebooster line 27 may be connected to an outlet of a booster pump (notshown). A lower end of the choke line 28 may have prongs connected torespective second branches of the flow crosses 41 m,b. Shutoff valves 45d,e may be disposed in respective prongs of the choke line lower end.

A pressure sensor 47 a may be connected to a second branch of the upperflow cross 41 u. Pressure sensors 47 b,c may be connected to the chokeline prongs between respective shutoff valves 45 d,e and respective flowcross second branches. Each pressure sensor 47 a-c may be in datacommunication with the control pod 76. The lines 27, 28 and umbilical 70may extend between the MODU 1 m and the PCA 1 p by being fastened tobrackets disposed along the riser 25. Each shutoff valve 45 a-e may beautomated and have a hydraulic actuator (not shown) operable by thecontrol pod 76.

Alternatively, the umbilical may be extend between the MODU and the PCAindependently of the riser. Alternatively, the valve actuators may beelectrical or pneumatic.

The fluid handling system 1 h may include a return line 29, mud pump 30,a solids separator, such as a shale shaker 33, one or more flow meters34 d,r, one or more pressure sensors 35 d,r, a variable choke valve,such as returns choke 36, a supply line 37 p,h, and a reservoir fordrilling fluid 60 d, such as a tank. A lower end of the return line 29may be connected to an outlet 26 o of the RCD 26 and an upper end of thereturn line may be connected to an inlet of the mud pump 30. The returnspressure sensor 35 r, returns choke 36, returns flow meter 34 r, andshale shaker 33 may be assembled as part of the return line 29. A lowerend of standpipe 37 p may be connected to an outlet of the mud pump 30and an upper end of Kelly hose 37 h may be connected to an inlet of thetop drive 5. The supply pressure sensor 35 d and supply flow meter 34 dmay be assembled as part of the supply line 37 p,h.

The returns choke 36 may include a hydraulic actuator operated by thePLC 75 via a hydraulic power unit (HPU) (not shown). The returns choke36 may be operated by the PLC 75 to maintain backpressure in the riser25. Each pressure sensor 35 d,r may be in data communication with thePLC 75. The returns pressure sensor 35 r may be operable to measurebackpressure exerted by the returns choke 36. The supply pressure sensor35 d may be operable to measure standpipe pressure.

Alternatively, the choke actuator may be electrical or pneumatic.

The returns flow meter 34 r may be a mass flow meter, such as a Coriolisflow meter, and may be in data communication with the PLC 75. Thereturns flow meter 34 r may be connected in the return line 29downstream of the returns choke 36 and may be operable to measure a flowrate of the drilling returns 60 r. The supply 34 d flow meter may be avolumetric flow meter, such as a Venturi flow meter and may be in datacommunication with the PLC 75. The supply flow meter 34 d may beoperable to measure a flow rate of drilling fluid 60 d supplied by themud pump 30 to the drill string 10 via the top drive 5. The PLC 75 mayreceive a density measurement of the drilling fluid 60 d from a mudblender (not shown) to determine a mass flow rate of the drilling fluidfrom the volumetric measurement of the supply flow meter 34 d.

Alternatively, the supply flow meter 34 d may be a mass flow meter or astroke counter of the mud pump 30.

To conduct a drilling operation, the mud pump 30 may pump drilling fluid60 d from the drilling fluid tank, through the pump outlet, standpipe 37p and Kelly hose 37 h to the top drive 5. The drilling fluid 60 d mayinclude a base liquid. The base liquid may be refined or synthetic oil,water, brine, or a water/oil emulsion. The drilling fluid 60 d mayfurther include solids dissolved or suspended in the base liquid, suchas organophilic clay, lignite, and/or asphalt, thereby forming a mud.

The drilling fluid 60 d may flow from the Kelly hose 37 h and into thedrill string 10 via the top drive 5 and open Kelly valve 11. Thedrilling fluid 60 d may flow down through the drill string 10 and exitthe drill bit 15, where the fluid may circulate the cuttings away fromthe bit and return the cuttings up an annulus 95 formed between an innersurface of the casing 91 or wellbore 90 and an outer surface of thedrill string 10. The returns 60 r (drilling fluid 60 d plus cuttings)may flow through the annulus 95 to the wellhead 50. The returns 60 r maycontinue from the wellhead 50 and into the riser 25 via the PCA 1 p. Thereturns 60 r may flow up the riser 25 to the RCD 26. The returns 60 rmay be diverted by the RCD 26 into the return line 29 via the RCD outlet26 o. The returns 60 r may continue through the returns choke 36 and theflow meter 34 r. The returns 60 r may then flow into the shale shaker 33and be processed thereby to remove the cuttings, thereby completing acycle. As the drilling fluid 60 d and returns 60 r circulate, the drillstring 10 may be rotated 16 by the top drive 5 and lowered by thetraveling block 6, thereby extending the wellbore 90 into the lowerformation 94 b.

The PLC 75 may be programmed to operate the returns choke 36 so that atarget bottomhole pressure (BHP) is maintained in the annulus 95 duringthe drilling operation. The target BHP may be selected to be within adrilling window defined as greater than or equal to a minimum thresholdpressure, such as pore pressure, of the lower formation 94 b and lessthan or equal to a maximum threshold pressure, such as fracturepressure, of the lower formation, such as an average of the pore andfracture BHPs.

Alternatively, the minimum threshold may be stability pressure and/orthe maximum threshold may be leakoff pressure. Alternatively, thresholdpressure gradients may be used instead of pressures and the gradientsmay be at other depths along the lower formation 94 b besidesbottomhole, such as the depth of the maximum pore gradient and the depthof the minimum fracture gradient. Alternatively, the PLC 75 may be freeto vary the BHP within the window during the drilling operation.

A static density of the drilling fluid 60 d (typically assumed equal toreturns 60 r; effect of cuttings typically assumed to be negligible) maycorrespond to a threshold pressure gradient of the lower formation 94 b,such as being equal to a pore pressure gradient. During the drillingoperation, the PLC 75 may execute a real time simulation of the drillingoperation in order to predict the actual BHP from measured data, such asstandpipe pressure from sensor 35 d, mud pump flow rate from the supplyflow meter 34 d, wellhead pressure from any of the sensors 47 a-c, andreturn fluid flow rate from the return flow meter 34 r. The PLC 75 maythen compare the predicted BHP to the target BHP and adjust the returnschoke 36 accordingly.

Alternatively, a static density of the drilling fluid 60 d may beslightly less than the pore pressure gradient such that an equivalentcirculation density (ECD) (static density plus dynamic friction drag)during drilling is equal to the pore pressure gradient. Alternatively, astatic density of the drilling fluid 60 d may be slightly greater thanthe pore pressure gradient.

During the drilling operation, the PLC 75 may also perform a massbalance to monitor for a kick (not shown) or lost circulation (notshown). As the drilling fluid 60 d is being pumped into the wellbore 90by the mud pump 30 and the returns 60 r are being received from thereturn line 29, the PLC 75 may compare the mass flow rates (i.e.,drilling fluid flow rate minus returns flow rate) using the respectiveflow meters 34 d,r. The PLC 75 may use the mass balance to monitor forformation fluid (not shown) entering the annulus 95 and contaminatingthe returns 60 r or returns entering the formation 94 b.

Alternatively, the return line 29 may further include a gas detector(not shown) assembled as part thereof and the gas detector may captureand analyze samples of the returns 60 r as an additional safeguard forkick detection during drilling. The gas detector may include a probehaving a membrane for sampling gas from the returns 60 r, a gaschromatograph, and a carrier system for delivering the gas sample to thechromatograph.

Upon detection of a kick or lost circulation, the PLC 75 may takeremedial action, such as diverting the flow of returns 60 r from anoutlet of the returns flow meter 34 r to a degassing spool (not shown).The degassing spool may include automated shutoff valves at each end anda mud-gas separator (MGS). A first end of the degassing spool may beconnected to the return line 29 between the returns flow meter 34 r andthe shaker 33 and a second end of the degasser spool may be connected toan inlet of the shaker. The MGS may include an inlet and a liquid outletassembled as part of the degassing spool and a gas outlet connected to aflare or a gas storage vessel. The PLC 75 may also adjust the returnschoke 36 accordingly, such as tightening the choke in response to a kickand loosening the choke in response to loss of the returns.

Alternatively, the booster pump may be operated during drilling tocompensate for any size discrepancy between the riser annulus and thecasing/wellbore annulus and the PLC may account for boosting in the BHPcontrol and mass balance using an additional flow meter. Alternatively,the PLC 75 may estimate a mass rate of cuttings (and add the cuttingsmass rate to the intake sum) using a rate of penetration (ROP) of thedrill bit or a mass flow meter may be added to the cuttings chute of theshaker and the PLC may directly measure the cuttings mass rate.

Alternatively, the RCD 26 may be used with a riserless drilling system.The RCD 26 may then be assembled as part of a riserless packageconnected to the annular BOP 47 a and the return line 29 and RCDumbilical 71 may extend from the riserless package to the MODU 1 m.Alternatively, the LMRP may further include a returns pump.Alternatively, the drilling system may be dual gradient including alifting fluid pump or compressor connected to the LMRP.

FIG. 2 illustrates the RCD 26. The RCD 26 may include a docking station,a bearing assembly 110, and a tachometer 200. The docking station may belocated adjacent to the waterline 2 s and may be submerged. The dockingstation may include the outlet 260 (not shown, see FIG. 1A), aninterface 26 i (not shown, see FIG. 1A), a housing 101, and a latch 102,103, 105. The housing 101 may be tubular and include one or moresections 101 a-c connected together, such as by flanged connections. Thehousing 101 may further include an upper flange 104 u connected to anupper housing section 101 a, such as by welding, and a lower flange 104f connected to a lower housing section 101 c, such as by welding. Theupper flange 104 u may connect the docking station to the slip joint 23and the lower flange may connect the housing 101 to the outlet 26 o.

The latch 102, 103, 105 may include a hydraulic actuator, such as apiston 102, one or more (two shown) fasteners, such as dogs 103, and abody 105. The latch body 105 may be connected to the housing 101, suchas by threaded couplings. A piston chamber may be formed between thelatch body 105 and a mid housing section 101 b. The latch body 105 mayhave openings formed through a wall thereof for receiving the respectivedogs 103. The latch piston 102 may be disposed in the piston chamber andmay carry seals isolating an upper portion of the chamber from a lowerportion of the chamber. A cam surface may be formed on an inner surfaceof the piston 102 for radially displacing the dogs 103. The latch body105 may further have a landing shoulder formed in an inner surfacethereof for receiving a protective sleeve (not shown) or the bearingassembly 110. The protective sleeve may be installed for operation ofthe drilling system is in an overbalanced mode.

Hydraulic passages (not shown) may be formed through the mid housingsection 101 b and may provide fluid communication between the interface26 i and respective portions of the hydraulic chamber for selectiveoperation of the piston 103. An RCD umbilical 71 (not shown, see FIG.1A) may have hydraulic conduits and may provide fluid communicationbetween the RCD interface 26 i and the HPU of the PLC 75.

The bearing assembly 110 may include a bearing pack 111, a housing sealassembly 113, 114, one or more strippers 115 u,b, and a catch, such as asleeve 112. The upper stripper 115 u may include a gland 116 g, an upperretainer 116 u, and a seal 120 u. The gland 116 g and the upper retainer116 u may be connected together, such as by threaded couplings. Theupper stripper seal 120 u may be longitudinally and torsionallyconnected to the upper retainer 116 u, such as by fasteners (not shown).The gland 116 g may be longitudinally and torsionally connected to arotating mandrel 111 m of the bearing pack 111, such as by threadedcouplings. The lower stripper 115 b may include a lower retainer 116 band a seal 120 b. The lower stripper seal 120 b may be longitudinallyand torsionally connected to the lower retainer 116 b, such as byfasteners (not shown). The lower retainer 116 b may be longitudinallyand torsionally connected to the rotating mandrel 111 m, such as bythreaded couplings.

Each stripper seal 120 u,b may be directional and oriented to sealagainst the drill pipe 10 p in response to higher pressure in the riser25 than the UMRP 20 (components thereof above the RCD 26). Each stripperseal 120 u,b may have a conical shape for fluid pressure to act againsta respective tapered surface 119 u,b thereof, thereby generating sealingpressure against the drill pipe 10 p. Each stripper seal 120 u,b mayhave an inner diameter slightly less than a pipe diameter of the drillpipe 10 p to form an interference fit therebetween. Each stripper seal120 u,b may be made from a flexible material, such as an elastomer orelastomeric copolymer, to accommodate and seal against threadedcouplings of the drill pipe 10 p having a larger tool joint diameter.

The drill pipe 10 p may be received through a bore of the bearingassembly 110 so that the stripper seals 120 u,b may engage the drillpipe. The stripper seals 120 u,b may provide a desired barrier in theriser 25 either when the drill pipe 10 p is stationary or rotating. Thelower stripper seal 120 b may be exposed to the returns 60 r to serve asthe primary seal. The upper stripper seal 120 u may be idle as long asthe lower stripper seal 120 b is functioning. Should the lower stripperseal 120 b fail, the returns 60 r may leak therethrough and exertpressure on the upper stripper seal 120 u via an annular fluid passage121 formed between the bearing mandrel 111 m and the drill pipe 10 p.

The bearing pack 111 may support the strippers 115 u,b from the catchsleeve 112 such that the strippers may rotate relative to the housing101 (and the catch sleeve). The bearing pack 111 may include one or moreradial bearings, one or more thrust bearings, and a self containedlubricant system. The lubricant system may include a reservoir having alubricant, such as bearing oil, and a balance piston in communicationwith the returns 60 r for maintaining oil pressure in the reservoir at apressure equal to or slightly greater than the returns pressure. Thebearing pack 111 may be disposed between the strippers 115 u,b and behoused in and connected to the catch sleeve 112, such as by threadedcouplings and/or fasteners.

The catch sleeve 112 may have a landing shoulder and a catch profileformed in an outer surface thereof. The bearing assembly 110 may befastened to the housing 101 by engagement of the dogs 103 with the catchprofile of the catch sleeve 112. The housing seal assembly 113, 114 mayinclude a body 113 carrying one or more seals, such as o-rings, and aretainer 114. The retainer 114 may be connected to the sleeve 112, suchas by threaded couplings (not shown), and the seal body 113 may betrapped between a shoulder of the catch sleeve 112 and the retainer 114.The housing seals may isolate an annulus formed between the housing 101and the bearing assembly 110. The catch sleeve 112 may be torsionallycoupled to the housing 101, such as by seal friction. The upper retainer116 u may have a landing shoulder and a catch profile formed in an innersurface thereof for retrieval of the bearing assembly 110 by a runningtool (not shown).

Alternatively, each of the housing 101 and the sleeve 112 may havemating anti-rotation profiles. Alternatively, each stripper seal 120 u,binner diameter may be equal to or slightly greater than the pipediameter. Alternatively, the latch may include a spring instead of or inaddition to one of the hydraulic ports. Alternatively, the latchactuator may be electric or pneumatic instead of hydraulic.Alternatively, the bearing assembly 110 may be non-releasably connectedto the housing 101. Alternatively, the docking station may be locatedabove the waterline 2 s and/or along the UMRP 20 at any other locationbesides a lower end thereof. Alternatively, the docking station may belocated at an upper end of the UMRP 20 and the slip joint 23 and bracketconnecting the UMRP to the rig may be omitted or the slip joint may belocked instead of being omitted. Alternatively, the docking station maybe assembled as part of the riser 25 at any location therealong or aspart of the PCA 1 p.

Alternatively, an active seal RCD may be used. The active seal RCD mayinclude one or more bladders (not shown) instead of the stripper sealsand may be inflated to seal against the drill pipe by injection ofinflation fluid. The active seal RCD bearing assembly may also serve asa hydraulic swivel to facilitate inflation of the bladders.Alternatively, the active seal RCD may include one or more packings andthe bearing assembly may have one or pistons for selectively engagingthe packings with the drill string.

FIGS. 3A and 3B illustrate the tachometer 200. FIG. 4A illustrates apocket 117 formed in the upper retainer 116 u for receiving a probe 210of the tachometer 200. FIGS. 4B and 4C illustrate a pocket 118 formed inthe upper flange 104 u for receiving a base 201 of the tachometer 200.FIG. 5 illustrates the probe 210.

The tachometer 200 may include the base 201 and the probe 210. The base201 may include an electronics package 203 and a wireless data coupling,such as an antenna 202 and a receiver of the electronics package. Thereceiver of the electronics package 203 may include an amplifier and ademodulator for processing a signal received from the probe 210. Theelectronics package 203 may be in communication with the interface 26 ivia leads or jumper cable (not shown) and further include a relay, suchas a modem, for transmitting data received from the probe 210 to the PLC75 via an electric cable of the RCD umbilical 71. The electronicspackage 203 may also be supplied with power by the electric cable of theRCD umbilical 71.

The base 201 may be longitudinally and torsionally connected to thehousing 101, such as by being disposed in the pocket 118 formed in theupper flange 104 u. The pocket 118 may include a receiver portion 118 rformed in an outer surface of the upper flange 104 u and an antennaportion 118 a formed in an inner surface of the upper flange forreceiving the respective electronics package 203 and the antenna 202. Areceiver cover 204 r may seal and retain the electronics package 203 inthe receiver pocket portion 118 r and an antenna cover 204 a may sealand retain the antenna 202 in the antenna pocket portion 118 a. One ormore fasteners may connect the receiver cover 204 r to the upper flange104 u and one or more fasteners may connect the antenna cover 204 a tothe upper flange. Leads (not shown) may connect the electronics package203 to the RCD interface 26 i.

Alternatively, the base 201 may include a transmitter and power sourcefor wireless communication with the PLC 75 instead of using the RCDumbilical 75.

The probe 210 may include a sensor package 211, a wireless datacoupling, such as an antenna 212 and a transmitter 213, and a powersource 214. Respective components of the probe 210 may be in electricalcommunication with each other by leads or a bus. The power source 214may be a battery. The probe 210 may be longitudinally and torsionallyconnected to the upper stripper 115 u, such as by being disposed in thepocket 117 formed in the upper retainer 116 u. The pocket 117 mayinclude a power portion 117 p, a transmitter portion 117 t, and a sensorportion 117 s, each formed in an upper surface of the upper retainer 116u, and an antenna portion 117 a formed in an outer surface of the upperretainer for receiving respective components of the probe 210. An uppercover 215 u may seal and retain the sensor package 211, transmitter 213,and power source 214 in the respective pocket portions 117 s,t,p and anantenna cover 215 a may seal and retain the antenna 212 in the antennapocket portion 117 a. One or more fasteners may connect the upper cover215 u to the upper retainer 116 u and one or more fasteners may connectthe antenna cover 215 a to the upper retainer.

Alternatively, the probe battery may be omitted and the probe may bepowered using wireless power couplings, further using the data couplingsas wireless power couplings, or adding a generator to the tachometer 200utilizing the rotation of the probe relative to the base to generateelectricity. The generator may deliver electricity to the probe and mayalso allow substitution of a capacitor for the probe battery.

The sensor package 211 may include a microcontroller (MPC) 211 m, a datarecorder 211 d, a clock (RTC) 211 c, an analog-digital converter (ADC)211 a, a pressure sensor 211 p, an angular speed sensor 211 r, a tiltsensor 211 v, and an angular acceleration sensor 211 t. The datarecorder 211 d may be a solid state drive. The pressure sensor 211 p maybe in fluid communication with the fluid passage 121 to monitorintegrity of the lower stripper 119 b.

The sensors 211 r,v,t may each be a single axis accelerometer and may beunidirectional or bidirectional. The accelerometers may bepiezoelectric, magnetostrictive, servo-controlled, reverse pendular, ormicroelectromechanical (MEMS). The tilt sensor 211 v may be orientedalong a longitudinal axis of the bearing assembly 110 to measureinclination relative to gravitational direction. Tilting of the bearingassembly 110 may be caused by misalignment of the top drive 5 with theUMRP 20, which may shorten the lifespan of the RCD 26. The angular speedsensor 211 r may be oriented along a radial axis of the bearing assembly110 to measure the centrifugal acceleration due to rotation of thebearing assembly for determining the angular speed. The angularacceleration sensor 211 t may be oriented along a circumferential axisof the bearing assembly 110. The angular acceleration sensor 211 t isdepicted as inclined between the radial and longitudinal axes fortwo-dimensional illustration.

Alternatively, the sensor package 211 may include any subset of thesensors 211 p,r,v,t instead of all of the sensors, including a subset ofonly one thereof. Alternatively, the angular speed 211 r sensor may be aproximity sensor, such as a Hall effect sensor. The sensor package 211may then have a Hall target and the base 201 may then have a Hallreceiver. The frequency of the Hall response may then be monitored todetermine angular speed and the amplitude of the Hall response may bemonitored to determine eccentricity of the bearing assembly rotation.Alternatively, the angular speed sensor 211 r may be a magnetometer.

The transmitter 213 may include an amplifier (AMP), a modulator (MOD),and an oscillator (OSC). Raw analog signals from the sensors may bereceived by the converter 211 a, converted to digital signals, andsupplied to the controller 211 m. The controller 211 m may process theconverted signals to determine the respective parameters, and send theprocessed data to the recorder 211 d for later recovery should thewireless data coupling fail. The controller 211 m may also multiplex theprocessed data and supply the multiplexed data to the transmitter 213.The transmitter 213 may then condition the multiplexed data and supplythe conditioned signal to the antenna 212 for electromagnetictransmission to the base antenna 202, such as at radio frequency. Thebase antenna 202 may receive the electromagnetic signal from the probeantenna 212 and supply the received signal to the electronics package203. The electronics package 203 may then relay the received signal tothe PLC 75 via the RCD umbilical 71. The probe controller 211 m mayiteratively monitor the sensors 211 p,r,t,v during drilling in realtime.

The PLC 75 may display the angular speed, pressure, tilt angle, andangular acceleration for the driller. The PLC 75 may determine bothinstantaneous angular speed and average angular speed (i.e., using fiveor more instantaneous measurements) and may display one or both for thedriller. The PLC 75 may also compare the angular speed to the angularspeed of the drill string 10 (received from the top drive 5) todetermine if the bearing assembly 110 is slipping relative to the drillstring. The PLC 75 may also monitor the sensor data to determinevibration of the drill string 10, such as stick-slip (torsionalvibration) from the angular acceleration data, bit-bounce (longitudinalvibration) from the tilt data, and/or whirl (lateral vibration) from theangular speed and angular acceleration data. The PLC 75 may includepredetermined criteria for monitoring health of the RCD 26. The PLC 75may compare the parameters to the criteria and predict remaininglifespan of the strippers 115 u,b and/or bearing pack 111. The remaininglifespan of the strippers 115 u,b may be forecasted either collectivelyor individually and display the prediction to the driller. The PLC 75may also make recommendations for adjustments to drilling parameters tooptimize remaining lifespan of the RCD 26.

Additionally, the probe 210 may include an antenna and receiver forreceiving telemetry signals from the drill string 10. The probe 210 maythen communicate the signals to the PLC 75 via the base 201.

The riser 25 and LMRP 20 may be filled with liquid when the bearingassembly 110 is installed into the docking station for managed pressuredrilling. As such, the antennas 202, 212 may be aligned and adjacentlypositioned to minimize attenuation of the radio frequency signaltransmitted from the probe antenna to the base antenna through theliquid medium. A gap formed between the antennas 202, 212 may bespecified, such as between two to four inches.

FIGS. 6A and 6B illustrate a gyroscope 400 usable with the probe 110,according to another embodiment of the present disclosure. The gyroscope400 may be used as the angular speed sensor 211 r instead of theaccelerometer, discussed above. The gyroscope 400 may have an innerframe 402 surrounded by an outer frame 404. Inner frame 402 may bedithered along a dither axis 410 through the use of a dither driver 406.The dither driver 406 may be formed with combs of drive fingers thatinterdigitate with fingers on the inner frame 402 and may be driven withalternating voltage signals to produce sinusoidal motion. The voltagesignal may be supplied by a modulator (not shown) and the voltage may besupplied at a frequency corresponding to a resonant frequency of theinner frame 402. The inner frame 402 may have one or more, such as four,elongated and parallel apertures that include the drive fingers. Adither sensor 408 may be formed by one or more, such as four, corners ofinner frame 402 having apertures that have dither pick-off fingers forsensing the dithering motion. The sensed dithering motion may be used asfeedback control for the dither driver 406.

In response to rotation of the bearing assembly 110 (about longitudinalaxis thereof, depicted by 412), inner frame 402 may be caused to movealong the Coriolis axis 414. Since the inner frame 402 may be ditheredrelative to outer frame 404 while being coupled thereto, the inner frame402 may drive the outer frame along the Coriolis axis 414. The gyro 400may further include a Coriolis sensor 405 for tracking this movement.The Coriolis sensor 405 may include fingers extending from the outerframe 404 along axes parallel to the dither axes and interdigitated withfirst and second fixed fingers anchored to the substrate. The firstfixed fingers may be connected to a first direct voltage source and thesecond fixed fingers may be connected to a second direct voltage sourcehaving a different voltage. As the outer frame 404 moves relative to thefixed fingers, the voltage on the outer frame changes and the size anddirection of movement can be determined.

This sensed Coriolis movement may be communicated to the controller 211m, which may then determine the angular speed of the bearing assembly110 as follows. If the dither motion is x=X sin(wt), the dither velocityis x′=wX cos(wt), where w is the angular frequency and is directlyproportional to the resonant frequency of the inner frame 402 by afactor of 2 pi. In response to an angular rate of motion R about thesensitive axis, a Coriolis acceleration y″=2Rx′ is induced along theCoriolis axis 414. The signal of the acceleration thus has the sameangular frequency w as dither velocity x′. By sensing the movement alongthe Coriolis axis 414, angular speed R can thus be determined.

FIG. 6B shows one-quarter of gyro 400. The other three quarters of thegyro 400 may be substantially identical to the portion shown. A ditherflexure mechanism 430 may be coupled between inner frame 402 and outerframe 404 to allow inner frame 402 to move along dither axis 410, but toprevent inner frame 402 from moving along Coriolis axis 414 relative toouter frame 404, but rather to move along Coriolis axis 414 only withouter frame 404.

The dither flexure 430 may have a dither lever arm 432 connected to theouter frame 404 through a dither main flexure 434, and connected toinner frame 402 through pivot flexures 436 and 438. Identical componentsmay be connected through a small central beam 440 to lever arm 432. Acentral beam 440 may encourage the lever arm 432 and the correspondinglever arm connected on the other side of beam 440 to move in the samedirection along dither axis 410. At the other end of lever arm 432,flexures 436 and 438 extend toward inner frame 402 at right angles toeach other to create a pivot point near the junction of flexures 436 and438.

Flexures 436 and 438 may be made long, thereby reducing tension for agiven dither displacement. The flexures 436 and 438 may be connected toinner frame 402 at points adjacent to the center of the inner frame inthe length and width directions. The two pivoting flexures may beperpendicular to each other. To keep lever arm 432 stiff compared tocentral beam 440, the lever arm 432 may be made wide.

To reduce the mass of the outer frame 404, a number of holes 444 maybecut out of outer frame 404. While the existence of holes 444 reduces themass, they do not have any substantial effect on the stiffness becausethey create, in effect, a number of connected I-beams. The outer frame404 may be coupled and anchored to the substrate through a connectionmechanism 450 and a pair of anchors 452 that are connected together.Connection mechanism 450 may include plates 453 and 454 connectedtogether with short flexures 456 and 458, which are perpendicular toeach other.

The masses and flexures may be made from a semiconductor, such asstructural polysilicon. The pivot points may be defined by flexures 456and 458 so that outer frame 404 can easily move perpendicular to thedither motion by pivoting plate 453 relative to plate 454 thereby givinga single bending action to flexures 456 and 458 at the ends and in thecenter. To accomplish this, the center beam 440 may be co-linear withthe pivot points.

Alternatively, the gyroscope may be any (other) embodiment discussedand/or illustrated in U.S. Pat. No. 6,122,961, which is hereinincorporated by reference in its entirety.

FIG. 7 illustrates an RCD 326 having a data sub 350, according toanother embodiment of the present disclosure. The RCD 326 may be similarto the RCD 26 except for the inclusion of the data sub 350. The data sub350 may include a base 351 and a probe 360. The base 351 may include anelectronics package 353 (similar to electronics package 203) and awireless data coupling, such as an antenna 352 and a receiver of theelectronics package. The base 351 may be longitudinally and torsionallyconnected to the housing 301, such as by the receiver 353 being disposedin a pocket formed in an upper flange of a lower housing section 301 cand the antenna 352 being disposed in a groove formed in an innersurface of the lower housing section. A jumper cable (not shown) mayconnect the receiver 353 to the RCD interface 26 i.

The probe 360 may include the sensor package (not shown), a wirelessdata coupling, such as an antenna 362, the transmitter 363 (similar totransmitter 213), and the power source (not shown, see power source214). The sensor package of the probe 360 may be similar to the sensorpackage 211 except for the substitution of a temperature sensor 311 tfor the pressure sensor 211 p. The temperature sensor 311 t may be influid communication with the bearing lubricant reservoir to monitorperformance of the bearing assembly 111. Components of the probe 360 maybe in electrical communication with each other by leads or a bus. Theprobe 360 may be longitudinally and torsionally connected to the catchsleeve 112, such as by the sensor package, transmitter, and power sourcebeing disposed in a pocket formed in a seal retainer 314 (the sealretainer may be connected to the sleeve 112, such as by threadedcouplings) and the antenna 352 being disposed in a groove formed in aninner surface of the seal retainer.

Since the probe 360 remains torsionally still relative to the strippers,the antennas may be circumferential instead of corresponding to a shapeof the respective pocket. The PLC 75 may utilize the still measurementsfrom the probe 360 to distinguish vibration components from thetachometer measurements. Further, the tilt measurement from the stillprobe 360 may be utilized by the PLC 75 in favor of the tachometer tiltmeasurement. The still probe 360 may also be utilized duringinstallation of the bearing assembly 310. The bearing assembly 310 maybe installed by being carried on the running tool assembled as part ofthe drill string 10. As the bearing assembly 310 enters the housing 301,the probe 360 may emit a homing signal. Detection of the homing signalby the tachometer receiver may establish a first reference point theretoand detection of the homing signal by the data sub receiver mayestablish a second reference point thereto. Further, the homing signalsmay be time stamped and detection lag time may be used from one or bothreceivers to pinpoint location of the bearing assembly 310 relative tothe housing 110.

While the foregoing is directed to embodiments of the presentdisclosure, other and further embodiments of the disclosure may bedevised without departing from the basic scope thereof, and the scope ofthe invention is determined by the claims that follow.

1. A rotating control device (RCD) for use with an offshore drillingunit, comprising: a tubular housing having a flange formed at each endthereof; a stripper seal for receiving and sealing against a tubular; abearing for supporting rotation of the stripper seal relative to thehousing; a retainer for connecting the stripper seal to the bearing; anda tachometer, comprising: a probe connected to the retainer andcomprising: a tilt sensor; an angular speed sensor; an angularacceleration sensor; a first wireless data coupling; and amicrocontroller operable to receive measurements from the sensors and totransmit the measurements to a base using the first wireless datacoupling; the base connected to the housing and comprising: a secondwireless data coupling operable to receive the measurements; and anelectronics package in communication with the second wireless datacoupling and operable to relay the measurements to the offshore drillingunit.
 2. The RCD of claim 1, wherein: the stripper seal is an upperstripper seal, the retainer is an upper retainer, and the RCD furthercomprises a lower stripper seal and a lower retainer for connecting thelower stripper seal to the bearing.
 3. The RCD of claim 2, wherein thetachometer further comprises a pressure sensor in communication with apathway for measuring pressure between the stripper seals.
 4. The RCD ofclaim 1, wherein the probe further comprises a battery.
 5. The RCD ofclaim 1, wherein the sensors are accelerometers.
 6. The RCD of claim 1,wherein the angular speed sensor is a gyroscope, comprising: an outerframe; an inner frame; a dither driver operable to dither the innerframe relative to the outer frame; and a Coriolis sensor for trackingmovement of the outer frame.
 7. The RCD of claim 1, wherein: thestripper seal, bearing, and retainer are part of a bearing assembly, thebearing is part of a bearing pack having a self contained lubricantsystem, the bearing assembly further comprises a catch sleeve, thehousing is part of a docking station, and the docking station furthercomprises a latch operable to engage the catch sleeve, thereby fasteningthe bearing assembly to the docking station.
 8. The RCD of claim 7,further comprising a data sub, comprising: a second probe connected tothe catch sleeve and comprising: a second tilt sensor; a temperaturesensor in fluid communication with the lubricant system; a thirdwireless data coupling; and a second microcontroller operable to receivemeasurements from the second tilt and temperature sensors and totransmit the measurements to a second base using the third wireless datacoupling; the second base connected to the housing and comprising: afourth wireless data coupling operable to receive the measurements; andan electronics package in communication with the fourth wireless datacoupling and operable to relay the measurements to the offshore drillingunit.
 9. The RCD of claim 8, wherein: the second tilt sensor is a firstaccelerometer, the second probe further comprises second and thirdaccelerometers, and the accelerometers are triaxially oriented.
 10. Amethod for drilling a subsea wellbore using the RCD of claim 1,comprising: injecting drilling fluid down a drill string while rotatingthe drill string having a drill bit located at a bottom of the subseawellbore, wherein the RCD is engaged with the drill string, therebydiverting returns from the wellbore to an outlet of the RCD; andmonitoring the measurements while drilling the wellbore.
 11. The methodof claim 10, wherein the measurements are monitored by forecasting aremaining lifespan of the stripper seal.
 12. The method of claim 11,wherein the lifespan is forecast using the tilt measurement.
 13. Themethod of claim 11, further comprising adjusting a drilling parameter tooptimize the remaining lifespan.
 14. The method of claim 10, wherein themeasurements are monitored by comparing the angular speed of the RCD tothe angular speed of the drill string.
 15. The method of claim 10,wherein the measurements are monitored by determining vibration of thedrill string.
 16. The method of claim 15, wherein the determinedvibration includes stick-slip, bit-bounce, and whirl.
 17. The method ofclaim 10, further comprising exerting backpressure on the returns. 18.The method of claim 10, further comprising, while drilling the wellbore:measuring a flow rate of the drilling fluid; measuring a flow rate ofthe returns; and comparing the returns flow rate to the drilling fluidflow rate to ensure control of an exposed formation adjacent to thewellbore.